When a fluid, such as oil and natural gas, is being produced from a subterranean reservoir through a wellbore the reservoir's ability to produce such fluids is often enhanced by processes that inject fluids and solids from the surface through a wellbore into subterranean reservoirs. There is one field of work that uses these fluids and is known to those familiar with the art of oil and gas production as stimulation fluids or hydraulic fracturing fluid, and the process involving these fluids is often referred to as hydraulic fracturing job or stimulation job. It is commonly believed that fracturing the subterranean rock in the reservoir will enhance hydrocarbon production from the well. This is accomplished by pumping the fluids at very high pressures that are greater than the fracture pressure of the subterranean reservoir, thus cracking the rock.
In early days explosives like nitroglycerin were dropped in wells to break up, crack, or otherwise stimulate the subterranean rock to produce fluids. These explosives had the limitation of only cracking the rock near the wellbore. Therefore, the idea of extending the fractures and cracks in the rocks far afield from the wellbore was developed using the injection of high pressure hydraulic fracturing fluids. The fluids injected as stimulation or fracture fluids are often mixed at surface with a variety of chemicals and solids prior to injection. Many fluid types are used including freshwater, saltwater, nitrogen, carbon dioxide, hydrogen peroxide, monopropellants, hydrogen fluoride, acids, bases, surfactants, alcohols, diesel, propane, liquid natural gas, with many combinations of these fluids and many more fluids. Some of these fluids are blended with solids like sand, bauxite, ceramic proppants, propellants, proppants, and/or catalysts and the fluid and solids are pumped as a slurry into the wellbore and reservoir rocks.
There are further chemicals and fluids mixed at the surface and injected with stimulation processes like acid stimulation jobs or steam injection stimulations to improve the reservoir's ability to produce back the injected stimulation fluids to surface and enhance the reservoir production of hydrocarbon fluids. This is because the stimulation fluids remaining in the rock matrix of the subterranean reservoir or the chemicals transported by the fluids reduce the reservoirs ability to produce commercial hydrocarbon fluids. Additionally, those familiar with the art of stimulation or fracture technology in the oil and gas industry often mix at surface viscosifier agents and/or cross-linkers to the stimulation fluid, enhancing the fluid's ability to transport solids into the reservoirs. What is needed is a method and apparatus to add large amounts of heat generated inside the well during well stimulation as opposed to generating heat at surface and transporting the heat down the well.
Further, current industry practice of adding to stimulation fluids chemicals such as hydroxypropyl guars, polyacryl imides, and cellulose gelling agents reduces the hydraulic friction between the fluids being pumped and the well conduits that transport the fluids from surface to the subterranean reservoir. These are often referred to as friction reducer chemicals. As the oil and gas industry continues to find more gas and oil in lower permeability rocks, and in ever lower pressured “resource plays,” like shale gas and coal bed methane, shale oil, and tar sands, it becomes ever more important to find substances to pump into the reservoir rock to enhance the hydrocarbon production by reducing the detrimental effects of the chemicals added for friction reduction.
Moreover, there is a problem with these methods when the fluids, particularly water, are produced back from the wells because they must be treated to re-use in subsequent wells or safely and environmentally disposed. There are many detrimental issues with this produced back fluid. For example, while flowing back from the subterranean environment, injected fluids containing friction reduction chemicals, gelling agents, scale inhibitors surfactants, crosslinkers, and hydrogen sulfide gas often contain bacteria that feed on the gels and poly acrylimdes and thus are not suitable for surface disposal or re-injection into subsequent wells during a subsequent stimulation, enhanced oil recovery method, or hydraulic fracture treatment. In the case of hydrogen sulfide gas production while flowing fluids from the wells, the ability to neutralize and treat this gas in the wellbore system would be a great improvement over the current art of flowing to facilities where the hydrogen sulfide (H2S) gas is stripped out with various ammine solutions. Moreover, the lack of water resources in areas of large hydrocarbon recovery restricts the use of water as a treatment fluid.
Before the current invention, methods to enhance production of hydrocarbons from wells used by those familiar with the art of treating stimulation fluids mixed friction reducers, gelling agents, cross linkers, and/or surfactants into water at surface prior to injecting the fluid and chemicals down a well casing or tubing. These chemicals are typically batch mixed into the stimulation fluids to be injected at the surface into large holding tanks, known as frac tanks, or the chemicals are added “on the fly” at surface to the stimulation or fracture fluid by injecting them into the discharge of a large centrifugal pump at the surface. The mixed fluid is then pumped through high pressure pumps and injected into the well and the reservoir at very high pressures and normally high injection rates thereby exceeding the fracture pressure of the reservoir rock. Hence the stimulation or rock fracturing is largely done with hydraulic forces.
This process, often referred to as “hydraulic fracturing,” is thought to crack or break the subterranean rock in the reservoir giving the reservoir more conductivity for the production of reservoir fluids like oil and gas. The objective is to put as much energy out away from the wellbore into the formation rock well beyond the wellbore to crack rock far field from the wellbore thereby improving the fluid conduction path from the far afield rock to the wellbore. Using current methods the hydraulic energy is highest at the wellbore where the stimulation or fracture chemicals enter into the well, and the energy available to crack and stimulate becomes progressively less as the stimulation and fracture fluids travel out beyond the wellbore. The typical method of treating heavy oil, tar sands, and depleted light oil reservoirs is to heat fresh water into steam and inject the steam into the wellbore once again concentrating most of the energy injected into the reservoir rock to near the wellbore. This stimulation or enhanced oil recovery method requires large amounts of fresh water, and the process loses considerable amounts of the heat energy in the transportation of the steam from surface to the subterranean environment.
A still further method of fracturing or stimulating subterranean rock reservoirs or stimulating subterranean reservoirs has been the dropping of explosives into the wells or injecting liquid and solid propellants, like nitroglycerin, dynamite and high grades of hydrogen peroxide, directly into reservoir rock. Hydrogen peroxide is known to decompose into hot water and oxygen in many reservoir rocks where the rocks act as a catalyst for the decomposition and no oxygen is required. The problem with this method is the very rapid and uncontrolled decomposition rate of hydrogen peroxide near the wellbore and the unpredictability of the reactivity of the reservoir rock as a catalyst.
It is desirable to use fluids with large chemical energy storage that do not require an oxygen environment to combust or decompose so that more chemical energy is available in the subterranean environment and may be placed far underground and far afield from the wellbore out into the reservoir to stimulate the subterranean reservoir with energy other than solely hydraulic energy, like heat and the expanding products of the fluids combustion and decomposition in the presence of catalyst, ignitors, and geothermal temperatures.
When a fluid, such as oil and natural gas, is being produced from a subterranean reservoir the reservoir energy depletes with time. It has been found that by the injection of certain fluids from the surface such as, nitrogen, water, steam, carbon dioxide, flue gas, air, and combinations of these fluids into a depleted or mature hydrocarbon reservoir the production of hydrocarbons from the depleted reservoir can be enhanced. There is one field of work that uses these fluids and is known to those familiar with the art of oil and gas production as Enhanced Oil Recovery, EOR. It is also known that the injection of heat can greatly enhance the injected fluid's ability to recover hydrocarbons from the depleted or mature reservoirs. This is particularly the case in “steam floods” and “steam assisted gravity drainage methods”, known as SAGD to those in the field of EOR, which uses injected steam from the surface but suffer from the heat loss as the steam is injected from surface and heat is lost along the length of the well and the surface pipe infrastructure in a field thereby delivering less heat energy to the subterranean reservoir. What is needed is a method to generate heat in-situ.
It has been found that by the injection of certain fluids like air, natural gas, oxygen, and combinations of these fluids into a depleted or mature hydrocarbon reservoir the production of hydrocarbons from the depleted reservoir can be enhanced by igniting the oil, natural gas, coal, tar sand, shale oil, shale gas, or kerogen located in-situ in the reservoir. The field of work that uses these burning fluids is known to those familiar with the art of oil and gas production as Fire Flooding or In-Situ retorting. It is known that the placement of heat in-situ can greatly enhance the fuel in-situ to ignite. This is particularly the case in tar sands and shale oil reservoirs. What is needed is a method to generate heat in-situ in the reservoir as far from the wellbore as possible with ignitable fluids or with fluids that will assist in the ignition of the in-situ reservoir fluids.
Additionally, enhanced oil recovery projects, in-situ retorting of shale oil, fire floods, and fracture and stimulation treatments are often performed in parts of the world that have high ambient surface temperatures, where the use of explosive and reactive fluids like hydrogen peroxide becomes more dangerous as these fluids become more reactive as their temperature increases at surface. Likewise, enhanced oil recovery projects, in-situ retorting, fire floods, fracture, and stimulation treatments are often performed in parts of the world that have low surface temperatures, such that the reactive fluids like hydrogen peroxide might freeze, rendering them unpumpable. Currently, when using water as the work fluid this cold condition is easily resolved by heating the working fluid, e.g. water, with heat exchangers for stimulation or EOR projects. The methods to maintain the temperatures on the surface of highly reactive mono-propellants for example is not currently available. What is needed are methods and apparatus to allow for the temperature control of high energy density fluids to allow them to be injected safely at well sites into wells.
For example currently, a hot oiler truck comes to the well that is to be stimulated with water fracture based fluids and, by burning propane on the truck's heat exchangers and passing the working fluid to be pumped into the well, the truck heats up the working fluid on the truck such that heated fluid passes through heat exchangers on the truck and at the same time passes the working fluid, usually water, to be used for the stimulation treatment over the truck's heat exchanger and then re-circulates the fracture treatment water back to a heated holding tank. In this way the fracture treatment water is heated in cold weather such that it can be pumped and does not get solid on the surface. However, this heating method of pumping the fluids into a heat exchanger on a truck that is burning propane is exceedingly dangerous when the fluids to be pumped are mono-propellants like hydrogen peroxide or hydrazine.
A still further need to transmit large amount of energy beyond the wellbore in an interval is known to those familiar with the art of enhanced oil recovery, EOR, and in-situ retorting of hydrocarbons. This need to get energy out into the subterranean reservoirs beyond the wellbore can also be extended to the new and evolving field of enhanced gas recovery, EGR, and fluid sequestering like CO2. In both EOR and EGR, there is a need to get energy down wellbores and out into the reservoir. Indeed, the method of horizontal wells for steam flooding was developed to allow the steam energy to contact larger portions of the subterranean reservoir.
A still further method of enhanced oil recovery, or indeed subterranean in-situ retorting of oil is to place large heaters in the earth to heat hydrocarbons and kerogens such that they can be produced from the subterranean intervals. Subterranean heaters, however, cannot heat large areas of the subterranean reservoir far afield from the wellbore because the heater is located in wellbore and the earth is a great heat sink. To improve the heating of the subterranean reservoir, one must drill either a large number of heater wells and add exceeding large amounts of heat in these wells from surface or drill very expensive and long horizontal wells in which heaters are placed. In all cases the desire is to get energy, and in the case of enhanced oil and gas recovery, heat energy large distances from the wellbore. In the case of oil shale, the immense amount of heat needed to remove the oil from the shale is not cost effective, hence a method is needed to ignite and to feed oxygen to the oil shale, using the in-situ generated heat from the combustion of some of the oil shale or kerogen to heat the oil shale reservoir. However, getting oxygen to the oil shale is not easy due to the shale's low inherent permeability which makes the injection of oxygen into the rock away from the wellbore very difficult. What is needed is a fluid that can heat the rock, ignite in the rock, and deliver oxygen to the rock while assisting in the burning of in-situ fluids.
What is needed is a method to transmit large amounts of energy beyond the wellbore in a subterranean interval being stimulated to enhance oil or gas production. A further need is to accomplish this far field from the injection wellbore for enhancement effect in the subterranean reservoir with substances that will not reduce the permeability of the reservoir or otherwise inhibit the reservoir to produce fluids back to the wellbore and to the surface. A further need is to reduce the environmental damage done on the surface of the earth and sea by the flow back to surface of stimulation and fracture fluids containing chemicals and bacteria. A still further need is to have available methods and apparatuses to safely handle and control the rate of reaction of reactive fluids and solids such as propellants, catalyst, and fuels pumped into subterranean environments like reservoir rocks at outdoor well sites that may have cold and hot surface environments. Many wells are located in locations on the earth where the surface temperatures are below the sublimation temperatures of many reactive mono-propellant fluids like hydrogen peroxide or hydrazine. What is needed is a method to keep these reactive high energy density substances, like liquid propellants, from freezing at well sites with cold surface temperatures.